The embodiments described herein relate generally to pumping systems, and more particularly, to methods and systems for selectively pumping a fluid, under a range of flow rates, out of a well casing of a wellbore based on a production fluid present in the well casing.
In producing petroleum and other useful fluids from production wells, some well assemblies include submersible pumping systems for raising the fluids collected in the well. Production fluids enter the well casing via perforations formed in the well casing adjacent a geological formation. Fluids contained in the geological formation collect in the well casing and may be raised by the submersible pumping system to a collection point above the surface of the earth.
Conventional pumping systems include a submersible pump, a submersible electric motor and a motor protector. The submersible electric motor typically supplies power to the submersible pump by a drive shaft, and the motor protector serves to isolate the motor from the well fluids. A deployment system, such as deployment tubing in the form of tubing strings, can be used to deploy the submersible pumping system within a wellbore. Generally, power is supplied to the submersible electric motor or motors by one or more power cables supported along the deployment system.
The rate at which fluids flow from the geological formation to the well casing can change significantly over time. In particular, hydrocarbons contained in shale formations are known to flow at decreasing rates over time. Conventional production wells may provide a high rate of fluid production in the early phase of the well life; and may provide a lower rate of fluid production for the remainder of the well life due to lower levels of available fluid. For example, it is common for fluid production from shale formations to drop to ⅙th of the initial production rate after 5 years. Producing the well at an efficient recovery rate may require the installation of an initial pumping system having a high flow rate in the early phase of well life and then replacing the initial pumping system with another pumping system having a lower flow rate one or more times over the life of the well. The temporal length of high rate production may be brief while requiring a costly high flow rate pumping system. Further, replacing pumping systems over the life of the well may increase design, operational, and/or maintenance costs of the well assembly.
Moreover, some well assemblies may pump fluid from two or more reservoirs that are present in the production formation by running separate submersible pumping systems deployed on separate tubing strings. Separate pumping systems, however, may be difficult to install and/or operate due to space constraints of the wellbore since the wellbore may need a diameter to accommodate separate pumping systems. Moreover, separate pumping systems may increase design, operational, and/or maintenance costs of the well.